Some oil (and other natural resource) recovery processes involve the conduction of hot fluids to/from an underground formation. For example, thermal recovery of a viscous oil, especially from a low permeability formation, may require heating devices and processes for the oil to be economically recoverable. In some of these thermal recovery devices and processes, heating is accomplished by injecting steam (from surface steam generating facilities) into the formation through a wellbore. Steam injection may be cyclic (e.g., "huff and puff") or long term (e.g., "steam drive fields"). The steam generation facilities must be sized for wellbore heat transmission losses, as well as the injection of steam in the underground formation.
Even if the wellbore is cased and cemented, the wellbore heat losses can be substantial and therefore costly. Wellbore heat losses during steam injection may decline with time but remain significant in typical steam drive or cyclic applications. The wellbore may also be used for purposes other than steam injection (e.g., oil production), requiring minimal flow obstruction or removal of the wellbore steam injection system.
The primary objectives of a wellbore steam injection system are to: (1) be easy to install into the wellbore; (2) conduct steam from the surface to the underground zone; (3) minimize thermal losses; (4) minimize wellbore flow obstruction or be removable; and (5) be able to handle a variety of fluid and environmental conditions. The steam injection piping should also be rugged in construction, easy to maintain, reliable, and low in cost. The system should also be capable of protecting other components from excessive heating.
Most of the current steam injection piping systems may do some of these objectives well, but other objectives may be accomplished poorly or not at all. One approach is to complete the well with an insulated tubular (i.e., insulated casing) cemented in the wellbore. An example of an insulated casing is Thermocase 750 vacuum insulated (i.e., double wall) tubular sections supplied by Kawasaki Thermal Systems, Inc., Tacoma, Washington. The insulated casing can be used directly for oil production or steam injection.
The well may also be conventionally completed (e.g., uninsulated tubulars or casing cemented in the wellbore) and a separate steam injection pipe or tubing string installed within the cased wellbore. The injection pipe is also typically centered within the casing.
The steam injection pipe may be uninsulated (i.e., bare). Although a bare steam injection pipe somewhat reduces thermal losses when compared with direct injection into a conventionally cased wellbore, the losses remain high. The bare steam injection pipe has the advantages of low initial cost and minimal flow obstruction (when compared to insulated tubulars). It also allows a corrosion resistant material to be used if necessary to contain the steam or other formation heating fluid.
However, the increasing cost of energy (i.e., high thermal losses) exacts an operating cost penalty for the advantages of bare steam injection piping. Related bare injection pipe problems include possible overheating/overstressing overstressing of the cemented casing, unacceptable steam quality (e.g., condensation of steam before reaching the formation face), and thermal shock (e.g., cold kill) failure of the cemented casing.
An insulated steam injection pipe is sometimes used to overcome some of these bare pipe losses and related problems. Smaller diameter Thermocase 750 vacuum insulated tubulars may be used for this insulated steam injection pipe application. In a further modification, only the most critical portions of the steam injection piping may be insulated to reduce the high cost of these installations.
Besides high initial cost, other problems with existing insulated steam injection piping are known. Vacuum insulated tubulars require special couplings, are essentially double the weight of bare pipe (double wall vacuum construction), and each pipe section must be protected against loads that would result in a loss of vacuum. The double wall also obstructs flow, creating steam flow pressure loss and/or annulus flow limitations, or requires a larger diameter and therefore more costly wellbore. Other problems include reliability (e.g., loss of vacuum over time) and limited flexibility (e.g., inability to bend into some deviated holes and potential abrasion damage during installation). The special couplings are not as effectively insulated as the remaining portions of the string. In addition, special coupling complexity may result in unreliable sealing, allowing still further steam/heat loss.
None of the current approaches known to the inventor eliminates the problem of high steam injection costs. Either high initial and handling costs of insulated tubulars or the high operating costs of bare steam injection pipe must be accepted.